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Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-i CHAPTER 11: LIFE-CYCLE COST SUBGROUP ANALYSIS

TABLE OF CONTENTS 11.1 INTRODUCTION

.................................................... 11-1 11.2 ANALYSIS APPROACH

.............................................. 11-1 11.2.1 Adjustment Factors for Analysis Inputs

.............................. 11-1 11.2.2How the Department Estimated The Adjustment Factors

................ 11-2 11.3 LIFE-CYCLE COST SUBGROUP RESULTS

.............................. 11-3 11.3.1 Municipal Utilities Subgroup Results

............................... 11-3 11.3.1.1 Design Line 1 Results

............................... 11-3 11.3.1.2 Design Line 2 Results

............................... 11-4 11.3.1.3 Design Line 3 Results

............................... 11-5 11.3.1.4 Design Line 4 Results

............................... 11-6 11.3.1.5 Design Line 5 Results

............................... 11-6 11.3.2Rural Cooperatives Subgroup Results

............................... 11-7 11.3.2.1 Design Line 1 Results

............................... 11-7 11.3.2.2 Design Line 2 Results

............................... 11-8 11.3.2.3 Design Line 3 Results

............................... 11-9 11.3.2.4 Design Line 4 Results

............................... 11-9 11.3.2.5 Design Line 5 Results

.............................. 11-10 11.4 PAYBACK PERIOD RESULTS

........................................ 11-11 11.4.1 Municipal Utilities Subgroup Results

.............................. 11-11 11.4.1.1 Design Line 1 Results

.............................. 11-11 11.4.1.2 Design Line 2 Results

.............................. 11-12 11.4.1.3 Design Line 3 Results

.............................. 11-13 11.4.1.4 Design Line 4 Results

.............................. 11-14 11.4.1.5 Design Line 5 Results

.............................. 11-14 11.4.2Rural Cooperatives Subgroup Results

.............................. 11-15 11.4.2.1 Design Line 1 Results

.............................. 11-15 11.4.2.2 Design Line 2 Results

.............................. 11-16 11.4.2.3 Design Line 3 Results

.............................. 11-17 11.4.2.4 Design Line 4 Results

.............................. 11-17 11.4.2.5 Design Line 5 Results

.............................. 11-18

LIST OF TABLES Table 11.2.1 Consumer Subgroup Economic Adjustment Factors

.................... 11-2 Table 11.3.1 Design Line 1 Results

........................................... 11-4DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-ii Table 11.3.2 Design Line 2 Results

........................................... 11-5 Table 11.3.3 Design Line 3 Results

........................................... 11-5 Table 11.3.4 Design Line 4 Results

........................................... 11-6 Table 11.3.5 Design Line 5 Results

........................................... 11-7 Table 11.3.6 Design Line 1 Results

........................................... 11-8 Table 11.3.7 Design Line 2 Results

........................................... 11-8 Table 11.3.8 Design Line 3 Results

........................................... 11-9 Table 11.3.9 Design Line 4 Results

.......................................... 11-10 Table 11.3.10Design Line 5 Results

.......................................... 11-10 Table 11.4.1 Design Line 1 Results

.......................................... 11-12 Table 11.4.2 Design Line 2 Results

.......................................... 11-13 Table 11.4.3 Design Line 3 Results

.......................................... 11-13 Table 11.4.4 Design Line 4 Results

.......................................... 11-14 Table 11.4.5 Design Line 5 Results

.......................................... 11-15 Table 11.4.6 Design Line 1 Results

.......................................... 11-16 Table 11.4.7 Design Line 2 Results

.......................................... 11-16 Table 11.4.8 Design Line 3 Results

.......................................... 11-17 Table 11.4.9 Design Line 4 Results

.......................................... 11-18 Table 11.4.10Design Line 5 Results

.......................................... 11-18DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-1 CHAPTER 11: LIFE-CYCLE COST SUBGROUP ANALYSIS

11.1 INTRODUCTION The life-cycle cost (LCC) subgroup analysis evaluates impacts on any identifiable groups of customers who may, because of their particular socio-economic characteristics, be disproportionately affected by any national energy-efficiency standard level. This chapter of the TSD describes how the Department performed its life-cycle cost consumer subgroup analysis for the distribution transformer energy-efficiency standard rulemaking. The Department conducted this evaluation for the Notice of Proposed Rulemaking (NOPR), in part, by analyzing the LCC and payback periods for those customers that fall into identified subgroups. For this rulemaking, the Department defined consumer subgroups in terms of retail utility ownership type. The specific consumer subgroups that the Department chose to examine are rural electric cooperatives and municipal utilities.

11.2 ANALYSIS APPROACH As part of the regular life-cycle cost analysis, the Department built spreadsheet analysis tools that provide a consumer economic analysis for a nationally representative sample of utilities. The Department developed a simplified approach to perform the consumer subgroup calculations. This approach adjusts the national data distributions for key analysis inputs by an appropriate scaling factor to produce an approximation of the input data for the consumer subgroup analysis. To estimate the economic impacts for the consumer subgroups, the Department then re-calculates the LCC with the adjusted input distributions. The subgroups examined are both subsets of the entire national electric utility sample and hence the analysis islimited to liquid-immersed distribution transformers, represented by design lines 1-5. The drytype distribution transformers, represented by design lines 6-13, were not included in the LCC subgroup analysis since electric utilities use few, if any, dry-type transformers. 11.2.1Adjustment Factors for Analysis Inputs The Department selected four key data inputs that it adjusted for the consumer subgroup analysis: 1. Cost of electricity 2. Transformer loading 3. Transformer selection A and B factors 4. Fraction of purchasers performing loss evaluationDRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-2The Department implemented these adjustment factors with an “LCC Subgroup” pulldown menu included as part of its LCC spreadsheet tool. Table 11.2.1 shows the adjustment factors for the national sample and the subgroups. Table 11.2.1 Consumer Subgroup Economic Adjustment Factors Subgroup Cost of Electricity Transformer

Loading A and B

Factors % Evaluators National sample 1.00 1.00 1.00 75 Rural cooperatives 0.98 0.75 0.90 100 Municipal utilities 0.93 1.20 1.00 100 11.2.2How the Department Estimated The Adjustment Factors This section describes how the Department estimated the four adjustment factors for each of the two selected consumer subgroups. For the cost of electricity, the Department examined the distribution of average electricity revenues per kWh for all utilities using EIA Form 861 data for different ownership classes (privately owned, cooperatives, and municipal utilities).1For the purposes of this analysis, the Department assumed that the EIA ownership classification of “Political Subdivision” corresponded to a type of municipal utility. This examination revealed that the distribution of unit revenues for different retail utility ownership classes is very similar. The Department then calculated the weighted average unit revenues for the different ownership classes of retail utilities. It found that the average unit revenue for rural cooperatives is 98 percent of that for the national sample and that average unit revenue for municipal utilities is 93 percent of that for the national sample. For transformer loading estimates, the data available to the Department consisted of rough loading estimates mentioned in stakeholder comments. The Department’s estimate of average root mean square (RMS) loading for a 50 kVA pad-mounted transformer for the national sample is 35 percent. Stakeholders commented that rural cooperative transformers tend to be loaded less because of oversizing for voltage flicker and lack of load diversity, while municipal utility transformers tend to have more diversity and subsequently higher loading. The typical rural cooperative transformer will serve a single customer while the typical urban transformer will serve multiple customers. Thus the Department estimated an adjustment factor of 0.75 for rural cooperatives, and 1.20 for municipal utilities, which results in average RMS loading estimates of 26 percent and 42 percent for 50 kVA transformers for rural cooperatives and municipal utilities, respectively.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-3 For customer evaluation A and B factors, the Department was given factors for rural cooperatives by the National Rural Electric Cooperative Association (NRECA) in stakeholder comments and compiled data from public sources for both municipal utilities and other entities. The Department found the evaluation parameters for rural cooperatives to be slightly lower than the national sample average and the parameters for municipal utilities to be approximately the same as the national sample average for the available data. For percent evaluators, the Department has not been given any examples of rural cooperatives or municipal utilities that do not evaluate losses for distribution transformer purchases. Thus the Department assumed the 100 percent evaluation case for rural cooperatives and municipal utilities.

11.3 LIFE-CYCLE COST SUBGROUP RESULTS This section presents the results of the LCC subgroups analysis for municipal utilities and rural electric cooperatives. The section presents the results for each subgroup and each design line in the form of tables that report the efficiency level, the mean LCC savings, and the fraction of transformers that have net savings, no impact, and net LCC cost (i.e., negative savings). 11.3.1Municipal Utilities Subgroup Results The LCC results for the municipal utilities subgroup are a reflection of two key features of this subgroup. The first key feature is that virtually all municipal utilities perform some type of economic evaluation of transformer losses when they make a purchase. This means that for those purchases, efficiency levels associated with the lower candidate standards are already economic for most transformers and there will be little or no impact from an efficiency standard. The second key feature is that transformers purchased by municipal utilities tend to serve more diverse, urban loads than transformers that serve more rural areas. The increased load diversity increases the load factor and the transformer loading, thus increasing the potential savings from reduced load losses. Thus, compared to the other subgroup (rural cooperatives), the benefits from efficiency improvements are on average greater. 11.3.1.1 Design Line 1 Results Table 11.3.1 presents the summary of the LCC subgroup analysis for municipal utilities for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 87 percent of the transformers are not impacted by candidate standard level (CSL) 1, while more than 93 percent of transformers are impacted by a CSL 4 standard level or higher. CSL 2 has similar fractions of affected transformers with net savings and net costs while CSLs 3, 5, and 6 have transformersDRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-4 dominated by those experiencing a net cost as a result of a standard. CSL 4 has a slight majority of affected transformers experiencing a net savings. There is a net average LCC savings for CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. For CSLs 1 through 5, the net average LCC impact is less than two percent of the average baseline LCC of $4,756. Table 11.3.1 Design Line 1 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.90 99.04 99.19 99.33 99.49 99.59 Transformers having LCC Savings > $0 (%) 8.7 16.0 25.6 58.8 34.8 8.6 Transformers having LCC Savings = $0 (%) 86.9 68.0 20.5 7.0 2.8 0.0 Transformers having LCC Savings < $0 (%) 4.4 16.0 54.0 34.3 62.4 91.4 Mean LCC Savings ($) 12 20 -29 78 -36 -675 11.3.1.2Design Line 2 Results Table 11.3.2 presents the summary of the LCC subgroup analysis for municipal utilities for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 89 percent of the transformers are not impacted by CSL 1, while more than 66 percent of transformers are impacted by a CSL 5 standard level or higher. CSL 4 has similar fractions of affected transformers with net savings and net costs, while CSLs 5 and 6 have transformers dominated by those experiencing a net cost as a result of a standard. CSLs 1 through 3 have the largest majority of affected transformers experiencing a net savings. There is a net average LCC savings for CSLs 1 through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1 through 5, the net average LCC impact is less than two percent of the average baseline LCC of $2,979.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-5 Table 11.3.2 Design Line 2 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.70 98.73 98.76 98.79 98.96 99.46 Transformers having LCC Savings > $0 (%) 9.7 10.6 13.6 14.8 14.6 0.7 Transformers having LCC Savings = $0 (%) 88.8 86.1 80.9 74.7 33.5 0.0 Transformers having LCC Savings < $0 (%) 1.6 3.3 5.5 10.6 51.9 99.4 Mean LCC Savings ($) 10 10 11 9 -40 -974 11.3.1.3Design Line 3 Results Table 11.3.3 presents the summary of the LCC subgroup analysis for municipal utilities for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that over 98 percent of the transformers are not impacted by CSL 1, while more than 94 percent of transformers are impacted by a CSL 4 standard level or higher. CSL 4 has similar fractions of affected transformers with net savings and net costs while CSLs 5 and 6 have transformers dominated by those experiencing a net cost as a result of a standard. CSLs 1 through 3 have the largest majority of affected transformers experiencing a net savings. There is a net average LCC savings for CSLs 1 through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1 through 5, the net average LCC impact is less than five percent of the average baseline LCC of $22,168. Table 11.3.3 Design Line 3 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 99.30 99.38 99.46 99.54 99.74 99.75 Transformers having LCC Savings > $0 (%) 1.5 11.0 27.9 45.9 25.2 21.9 Transformers having LCC Savings = $0 (%) 98.3 87.7 65.8 5.6 0.2 0.0 Transformers having LCC Savings < $0 (%) 0.2 1.3 6.3 48.6 74.6 78.1 Mean LCC Savings ($) 54 259 734 833 -1,177 -1,804DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-6 11.3.1.4Design Line 4 Results Table 11.3.4 presents the summary of the LCC subgroup analysis for municipal utilities for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that more than 85 percent of the transformers are not impacted by CSL 1, while more than 85 percent of transformers are impacted by a CSL 3 standard level or higher. CSL 4 has similar fractions of affected transformers with net savings and net costs while CSLs 3, 5, and 6 have transformers dominated by those experiencing a net cost as a result of a standard and CSLs 1 and 2 have the majority of affected transformers obtaining a net savings from a standard. There is a net average LCC savings for CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. For CSLs 1 through 5, the net average LCC impact is less than a few percent of the average baseline LCC of $11,844. Table 11.3.4 Design Line 4 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.90 99.08 99.26 99.45 99.58 99.61 Transformers having LCC Savings > $0 (%) 11.5 29.0 30.3 46.8 29.5 20.8 Transformers having LCC Savings = $0 (%) 85.7 53.4 14.6 12.3 1.0 0.0 Transformers having LCC Savings < $0 (%) 2.9 17.6 55.1 40.9 69.5 79.2 Mean LCC Savings ($) 112 249 -43 302 -206 -773 11.3.1.5Design Line 5 Results Table 11.3.5 presents the summary of the LCC subgroup analysis for municipal utilities for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that 96 percent of the transformers are not impacted by CSL 1, while more than 68 percent of transformers are impacted by a CSL 3 standard level or higher. CSLs 5 and 6 have transformers dominated by those incurring a net cost as a result of a standard and CSLs 1 through 4 have the majority of affected transformers obtaining a net savings from a standard. There is a net average LCC savings for all CSLs. For CSLs 1 through 5, the net average LCC impact is less than five percent of the average baseline LCC of $65,545.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-7 Table 11.3.5 Design Line 5 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 99.30 99.36 99.42 99.47 99.71 99.71 Transformers having LCC Savings > $0 (%) 3.9 15.1 36.0 51.1 40.3 40.8 Transformers having LCC Savings = $0 (%) 96.0 83.8 53.2 31.2 0.1 0.1 Transformers having LCC Savings < $0 (%) 0.1 1.2 10.9 17.7 59.7 59.2 Mean LCC Savings ($) 429 1,253 2,174 3,157 1,524 1,580 11.3.2Rural Cooperatives Subgroup Results The LCC results for the rural cooperatives subgroup are a reflection of two key features of this subgroup. The first key feature is that virtually all rural cooperatives perform some type of economic evaluation of transformer losses when they make a purchase. This means that for those purchases, efficiency levels associated with the lower candidate standards are already economic for most transformers and there will be little or no impact from an efficiency standard. The second key feature is that distribution transformers purchased by rural cooperatives tend to serve smaller loads than transformers that serve urban areas. The lower loading decreases the potential savings from reduced load losses and thus the benefits from efficiency improvements are on average less than the national average case per affected transformer. 11.3.2.1 Design Line 1 Results Table 11.3.6 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 86 percent of transformers are impacted by a CSL 1 standard level while 97 percent of transformers are impacted by a CSL 4 standard level. There is a net average LCC savings from CSLs 1 and 4, while there is a net average LCC cost for CSLs 2, 3, 5, and 6. For all standard levels except CSL 6, the net average LCC impact is less than five percent of the average baseline LCC of $4,402.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-8 Table 11.3.6 Design Line 1 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.90 99.04 99.19 99.33 99.49 99.59 Transformers having LCC Savings > $0 (%) 8.04 11.12 18.59 63.93 28.17 1.82 Transformers having LCC Savings = $0 (%) 85.57 67.18 15.20 2.89 1.24 0.00 Transformers having LCC Savings < $0 (%) 6.39 21.70 66.21 33.18 70.59 98.18 Mean LCC Savings ($) 8 -15 -134 89 -147 -890 11.3.2.2Design Line 2 Results Table 11.3.7 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 87 percent of rural cooperative transformers are not impacted by a CSL 1 standard level while nearly 75 percent of transformers are impacted by a CSL 5 standard level. Transformers that incur a net LCC cost resulting from a standard dominate the affected transformers for candidate standard levels 5 and 6, while CSLs 1 through 3 have more affected transformers with net savings and CSL 4 has approximately equal numbers of affected transformers that incur net costs and net savings. There is a net average LCC savings for CSLs 1, 2, 3, and 4, while there is a net average LCC cost for CSLs 5 and 6. For all standard levels except CSLs 5 and 6, the net average LCC impact is less than one percent of the average baseline LCC of $2,821. Table 11.3.7 Design Line 2 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.70 98.73 98.76 98.79 98.96 99.46 Transformers having LCC Savings > $0 (%) 11.2 13.2 14.1 15.8 11.2 0.1 Transformers having LCC Savings = $0 (%) 86.6 81.6 77.1 69.7 25.4 0.0 Transformers having LCC Savings < $0 (%) 2.2 5.2 8.8 14.5 63.5 99.9 Mean LCC Savings ($) 11 11 9 6 -72 -1,073DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-9 11.3.2.3Design Line 3 Results Table 11.3.8 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 98 percent of the transformers are not impacted by CSL 1, while more than 97 percent of transformers are impacted by a CSL 4 standard level or higher. CSLs 4 through 6 have transformers dominated by transformers with a net cost as a result of a standard and CSLs 1 through 3 have the majority of affected transformers incurring a net savings. There is a net average LCC savings for CSLs 1 through 4, while there is a net average LCC cost for CSLs 5 and 6. For CSLs 1 through 4, the net average LCC impact is less than five percent of the average baseline LCC of $17,633. Table 11.3.8 Design Line 3 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 99.30 99.38 99.46 99.54 99.74 99.75 Transformers having LCC Savings > $0 (%) 2.1 10.4 22.8 35.3 7.8 5.7 Transformers having LCC Savings = $0 (%) 97.8 86.9 64.7 2.7 0.1 0.0 Transformers having LCC Savings < $0 (%) 0.1 2.7 12.4 62.0 92.1 94.3 Mean LCC Savings ($) 40 133 250 58 -3,188 -4,106 11.3.2.4Design Line 4 Results Table 11.3.9 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that more than 85 percent of the transformers are not impacted by CSL 1, while more than 91 percent of transformers are impacted by a CSL 3 standard level or higher. CSL 4 has similar fractions of affected transformers with net savings and net costs while CSLs 2, 3, 5, and 6 have transformers dominated by those experiencing a net cost as a result of a standard. CSLs 1 and 2 have the majority of affected transformers obtaining a net savings from a standard. There is a net average LCC savings for CSLs 1, 2, and 4, while there is a net average LCC cost for CSLs 3, 5, and 6. For CSLs 1 through 5, the net average LCC impact is less than a few percent of the average baseline LCC of $10,391.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-10 Table 11.3.9 Design Line 4 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 98.90 99.08 99.26 99.45 99.58 99.61 Transformers having LCC Savings > $0 (%) 9.7 21.7 28.8 46.0 13.6 6.9 Transformers having LCC Savings = $0 (%) 85.3 50.9 8.4 7.9 0.8 0.0 Transformers having LCC Savings < $0 (%) 5.0 27.5 62.8 46.1 85.6 93.1 Mean LCC Savings ($) 45 19 -220 80 -918 -1,637 11.3.2.5Design Line 5 Results Table 11.3.10 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that nearly 96 percent of the transformers are not impacted by CSL 1, while more than 71 percent of transformers are impacted by a CSL 3 standard level or higher. CSLs 5 and 6 have transformers dominated by those incurring a net cost as a result of a standard and CSLs 1 through 4 have the majority of affected transformers incurring a net savings from a standard. There is a net average LCC savings for CSLs 1 through 4. For CSLs 1 through 5, the net average LCC impact is less than two percent of the average baseline LCC of $46,773. Table 11.3.10Design Line 5 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Efficiency (%) 99.30 99.36 99.42 99.47 99.71 99.71 Transformers having LCC Savings > $0 (%) 3.9 14.4 28.2 38.0 11.1 11.4 Transformers having LCC Savings = $0 (%) 95.7 82.9 51.4 28.8 0.1 0.0 Transformers having LCC Savings < $0 (%) 0.4 2.7 20.4 33.3 88.9 88.6 Mean LCC Savings ($) 199 507 597 660 -6,229 -6,226DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-11 11.4 PAYBACK PERIOD RESULTS As described in more detail in section 8.6, a common technique for evaluating investment decisions is to perform a payback period (PBP) analysis. A more energy-efficient device will usually cost more to purchase than a device of standard energy efficiency, while the more efficient device will usually cost less to operate. Operating expenses decrease due to a reduction in energy use. The payback period is the time (usually expressed in years) it takes to recover the additional first cost of the efficiency device with its energy cost savings. Because the Department analyzes the economics of a nationally representative distribution of transformers, DOE provides results in terms of a distribution of payback periods. There are several potential complications to performing an analysis of a distribution of PBP estimates that are discussed in more detail in section 8.6. Specifically, a payback period is a ratio of increased first cost and decreased operating expenses. When there is a distribution of changes for both first cost and operating expense reductions, the average of the ratio does not equal the ratio of the averages. Therefore, in the tables below, the Department reports all quantities of interest: the mean PBP, the average increase in first cost, and the average decrease in annual operating expenses (in the first year of operation). These quantities allow stakeholders to compare the average PBP to a ratio of the average first cost increase and the average operating cost decrease. These two values are comparable, but not equal because not all transformer purchase decision computations have well-defined PBPs. 11.4.1Municipal Utilities Subgroup Results The PBP results for the municipal utilities subgroup are a reflection of two key features of this subgroup. The first key feature is that virtually all municipal utilities perform some type of economic evaluation of transformer losses when they make a purchase. This means that for those purchases, efficiency levels associated with the lower candidate standards are already economic for most transformers and there will be little or no impact from an efficiency standard. The second key feature is that distribution transformers purchased by municipal utilities tend to serve more diverse, urban loads than transformers that serve more rural areas. The increased load diversity increases the load factor and the transformer loading, thus increasing the potential savings from reduced load losses. Compared to the rural cooperatives subgroup, the benefits from efficiency improvements are on average greater and the PBP tends to be slightly smaller than that for rural cooperatives. 11.4.1.1 Design Line 1 Results Table 11.4.1 presents the summary of the PBP subgroup analysis for municipal utilities for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 87 percent of theDRAFT

a Undefined refers to all invalid PBP computations. See section 8.6 for a full discussion. Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-12 transformers are not impacted by CSL 1, while more than 93 percent of transformers are impacted by a CSL 4 standard level or higher. UndefinedaPBPs remain below 4 percent for all CSLs. Mean distribution PBPs for this design line range from 16.9 to 47.2 years, with the minimum distribution PBP seen for CSL 4. Table 11.4.1 Design Line 1 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback (Years) 20.6 29.7 39.9 16.9 25.5 47.2 Transformers Not Impacted by the Standard (%) 86.9 68.0 20.5 7.0 2.8 0.0 Transformers having Well-Defined Payback Period (%) 12.2 30.7 75.9 92.5 97.1 99.6 Transformers having Undefined Payback Period (%) 0.9 1.3 3.7 0.5 0.1 0.5 Mean Incremental First Cost ($) 137 257 385 422 757 1545 Mean Operating Cost Savings ($) 11 14 15 26 34 40 11.4.1.2Design Line 2 Results Table 11.4.2 presents the summary of the PBP subgroup analysis for municipal utilities for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 89 percent of the transformers are not impacted by CSL 1, while more than 66 percent of transformers are impacted by a CSL 5 standard level or higher. Undefined PBPs are below 4 percent for all CSLs. Mean PBPs for this design line range from 10.9 to 72.4 years, with a monotonic increase in mean PBP with increasing candidate standard level.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-13 Table 11.4.2 Design Line 2 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 10.9 16.0 17.2 22.5 39.1 72.4 Transformers Not Impacted by the Standard (%) 88.8 86.1 80.9 74.7 33.5 0.0 Transformers having Well-Defined Payback Period (%) 8.9 12.7 16.5 22.4 63.0 100.0 Transformers having Undefined Payback Period (%) 2.4 1.2 2.6 2.9 3.5 0.0 Mean Incremental First Cost ($) 28 45 52 76 212 1,418 Mean Operating Cost Savings ($) 6 6 5 5 7 21 11.4.1.3Design Line 3 Results Table 11.4.3 presents the summary of the PBP subgroup analysis for municipal utilities for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that over 98 percent of the transformers are not impacted by CSL 1, while more than 94 percent of transformers are impacted by a CSL 4 standard level or higher. Undefined PBPs remain below 5 percent for all CSLs. For this design line, PBPs increase monotonically from 3.6 to 34.6 years with increasing CSL. Table 11.4.3 Design Line 3 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 3.6 8.1 13.8 23.6 31.7 34.6 Transformers Not Impacted by the Standard (%) 98.3 87.7 65.8 5.6 0.2 0.0 Transformers having Well-Defined Payback Period (%) 1.2 11.9 33.6 90.1 99.8 100.0 Transformers having Undefined Payback Period (%) 0.5 0.5 0.6 4.3 0.0 0.0 Mean Incremental First Cost ($) 236 591 1,053 1,498 7,859 8,940 Mean Operating Cost Savings ($) 155 115 131 104 300 317DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-14 11.4.1.4Design Line 4 Results Table 11.4.4 presents the summary of the PBP subgroup analysis for municipal utilities for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that more than 85 percent of the transformers are not impacted by CSL 1, while more than 85 percent of transformers are impacted by a CSL 3 standard level or higher. For this design line, transformers with undefined PBPs are one percent or fewer of all transformers. Mean distribution PBP ranges from 14.3 to 36.7 years with the Department calculating second lowest mean PBP for CSL 4. Table 11.4.4 Design Line 4 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 14.3 21.7 26.3 19.0 30.6 36.7 Transformers Not Impacted by the Standard (%) 85.7 53.4 14.6 12.3 1.0 0.0 Transformers having Well-Defined Payback Period (%) 13.3 45.9 84.5 87.6 98.8 99.9 Transformers having Undefined Payback Period (%) 1.0 0.8 1.0 0.0 0.2 0.1 Mean Incremental First Cost ($) 411 688 1,384 1,731 3,029 3,880 Mean Operating Cost Savings ($) 51 51 67 103 130 140 11.4.1.5Design Line 5 Results Table 11.4.5 presents the summary of the PBP subgroup analysis for municipal utilities for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that 96 percent of the transformers are not impacted by CSL 1, while more than 68 percent of transformers are impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 2 percent of transformers for all CSLs. Mean distribution PBP ranges from 4.3 to 26.8 years and increases monotonically with CSL.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-15 Table 11.4.5 Design Line 5 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 4.3 8.1 15.5 16.0 27.0 26.8 Transformers Not Impacted by the Standard (%) 96.0 83.8 53.2 31.2 0.1 0.1 Transformers having Well-Defined Payback Period (%) 4.0 16.1 45.4 67.7 99.9 99.9 Transformers having Undefined Payback Period (%) 0.1 0.2 1.4 1.1 0.0 0.0 Mean Incremental First Cost ($) 1,343 1,786 2,243 3,510 18,239 18,352 Mean Operating Cost Savings ($) 497 391 281 340 867 880 11.4.2Rural Cooperatives Subgroup Results The PBP results for the rural cooperatives subgroup are a reflection of two key features of this subgroup. The first key feature is that virtually all rural cooperatives perform some type of economic evaluation of transformer losses when they make a purchase. This means that for those purchases, efficiency levels associated with the lower candidate standards are already economic for most transformers and there will be little or no impact from an efficiency standard. The second key feature is that distribution transformers purchased by rural cooperatives tend to serve smaller loads than transformers that serve urban areas. The lower loading decreases the potential savings from reduced load losses, and thus the benefits from efficiency improvements are on average less than the national average case per affected transformer, and payback times will be longer than the national average. 11.4.2.1 Design Line 1 Results Table 11.4.6 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 1, a 50 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 86 percent of transformers are impacted by a CSL 1 standard level, while 97 percent of transformers are impacted by a CSL 4 standard level. Undefined paybacks remain below 3 percent for all CSLs except CSL 3. CSL 4 has the minimum mean distribution PBP of all CSLs which range from 16.3 to 53.8 years.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-16 Table 11.4.6 Design Line 1 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 25.4 38.9 49.5 16.3 27.1 53.8 Transformers Not Impacted by the Standard (%) 85.6 67.2 15.2 2.9 1.2 0.0 Transformers having Well-Defined Payback Period (%) 12.9 29.9 77.4 96.8 98.4 99.1 Transformers having Undefined Payback Period (%) 1.5 2.9 7.4 0.3 0.3 1.0 Mean Incremental First Cost ($) 142 265 374 423 759 1560 Mean Operating Cost Savings ($) 9 10 10 27 31 32 11.4.2.2Design Line 2 Results Table 11.4.7 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 2, a 25 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 87 percent of rural cooperative transformers are not impacted by a CSL 1 standard level, while nearly 75 percent of transformers are impacted by a CSL 5 standard level. Undefined PBPs remain below 6 percent for all CSLs. Mean PBPs for this design line range from 12.4 to 80.0 years, with a monotonic increase in mean PBP with increasing candidate standard level. Table 11.4.7 Design Line 2 Results Candidate Standard Level 1 (TP1) 2 3 4 5 6 Mean Payback Period (Years) 12.4 17.6 20.3 24.9 45.4 80.0 Transformers Not Impacted by the Standard (%) 86.6 81.6 77.1 69.7 25.4 0.0 Transformers having Well-Defined Payback Period (%) 10.6 16.1 19.0 25.0 69.0 100.0 Transformers having Undefined Payback Period (%) 2.8 2.3 3.9 5.3 5.6 0.0 Mean Incremental First Cost ($) 27 43 53 74 220 1,448 Mean Operating Cost Savings ($) 6 5 5 5 6 19DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-17 11.4.2.3Design Line 3 Results Table 11.4.8 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, the Department forecasts that nearly 98 percent of the transformers are not impacted by CSL 1, while more than 97 percent of transformers are impacted by a CSL 4 standard level or higher. Undefined PBPs remain below 3 percent for all CSLs. For this design line, PBPs increase monotonically from 3.9 to 43.3 years with increasing CSL. Table 11.4.8 Design Line 3 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 3.9 13.1 21.7 27.2 38.8 43.3 Transformers Not Impacted by the Standard (%) 97.8 86.9 64.7 2.7 0.1 0.0 Transformers having Well-Defined Payback Period (%) 1.5 12.5 34.2 94.8 99.9 100.0 Transformers having Undefined Payback Period (%) 0.7 0.6 1.1 2.5 0.0 0.0 Mean Incremental First Cost ($) 205 593 1,044 1,487 7,932 8,999 Mean Operating Cost Savings ($) 108 73 77 74 229 234 11.4.2.4Design Line 4 Results Table 11.4.9 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that more than 85 percent of the transformers are not impacted by CSL 1, while more than 91 percent of transformers are impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 2 percent of transformers for all CSLs. Mean distribution PBP ranges from 19.7 to 42.4 years with the Department calculating lowest mean PBP for CSL 4.DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-18 Table 11.4.9 Design Line 4 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 21.3 30.8 30.2 19.7 34.8 42.4 Transformers Not Impacted by the Standard (%) 85.3 50.9 8.4 7.9 0.8 0.0 Transformers having Well-Defined Payback Period (%) 12.8 47.4 91.4 92.0 98.5 99.7 Transformers having Undefined Payback Period (%) 1.9 1.8 0.2 0.1 0.7 0.3 Mean Incremental First Cost ($) 400 679 1,419 1,741 3,110 3,958 Mean Operating Cost Savings ($) 32 32 60 94 106 111 11.4.2.5Design Line 5 Results Table 11.4.10 presents the summary of the LCC subgroup analysis for rural cooperatives for the representative unit from design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, the Department forecasts that nearly 96 percent of the transformers are not impacted by CSL 1, while more than 71 percent of transformers are impacted by a CSL 3 standard level or higher. Undefined PBPs remain below 3 percent of transformers for all CSLs. Mean distribution PBP ranges from 7.7 to 32.8 years and increases monotonically with increasing CSL. Table 11.4.10Design Line 5 Results Candidate Standard Level 1 (TP 1) 2 3 4 5 6 Mean Payback Period (Years) 7.7 12.6 23.4 21.3 32.7 32.8 Transformers Not Impacted by the Standard (%) 95.7 82.9 51.4 28.8 0.0 0.0 Transformers having Well-Defined Payback Period (%) 4.2 16.8 46.3 70.5 99.8 99.8 Transformers having Undefined Payback Period (%) 0.1 0.3 2.3 0.7 0.2 0.2 Mean Incremental First Cost ($) 1,363 1,820 2,192 3,429 18,716 18,647 Mean Operating Cost Savings ($) 288 232 167 223 668 662DRAFT

Transformer_DRAFT_TSD_Chapter11_version8-02-05_DOE_8/2/05 11-19 REFERENCES 1. U.S. Department of Energy - Energy Information Administration.Form EIA-861: Annual Electric Utility Data.2001.(Last accessed July, 2005.) This material is available in Docket #83. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <http://www.eia.doe.gov/cneaf/electricity/page/eia861.html>